The present invention relates to the removal of sulfur oxides and nitrogen oxides from the flue gases of combustion apparatus which burn high sulfur fuels. Boilers, fired heaters and other combustion devices and systems which burn high sulfur fossil fuels such as coal, petroleum coke, heavy fuel oil and other bituminous fuels produce flue gases containing about 1,000 to about 3,000 ppm of sulfur oxides and about 700 to about 1,500 ppm of nitrogen oxides or NOX. The majority of these sulfur oxide emissions in the United States are from electric utilities and industrial power plants.
Numerous processes have been developed over the years to remove sulfur dioxide from stack gases. Other processes and combustion technology have been developed to reduce NOX emissions. Most of the current sulfur oxide removal processes use some type of alkali scrubbing techniques wherein the sulfur oxides are absorbed in alkali solutions of limestone. The sulfur oxides are precipitated from such solutions and are ultimately disposed of as a solid waste. These flue gas scrubbing processes not only consume large quantities of chemicals but also produce additional waste materials which must be disposed of. Furthermore, these alkali scrubbing systems do not remove any of the nitrogen oxides contained in the flue gas. The sulfur removal efficiency of these scrubbing methods is claimed to be between 50 and 90 percent of the sulfur oxide content.
In the United States, environmental regulations, including the "Acid Rain Act" (Clean Air Act), require the power industry of the coutry to remove additional percentages of sulfur oxides and nitrogen oxides from the flue gases of combustion apparatus. Further, state and local legislation is now being enacted to limit the quantities of sulfur-bearing solid wastes which can be sent to landfill space.
The recovery of sulfur from the flue gases of combustion apparatus is complicated by the relative dilute concentrations of sulfur oxides therein and the presence of excess oxygen and particulate matter in such gases. In recent years oil refinery sulfur plants have employed tail gas treating processes to reduce the emissions of sulfur oxides from such plants. Sulfur oxide emissions from refineries are about 10 times as concentrated as the sulfur oxides in boiler flue gases. The present invention utilizes a novel approach to the recovery of sulfur which combines adsorption technology to concentrate the toxic substances contained in the stack gas of combustion apparatus and refinery sulfur plant tail gas technology to recover elemental liquid sulfur and remove NOX. Thus, sulfur oxides are first removed from the stack gas of the combustion apparatus as a more concentrated stream and then such stream is converted to elemental liquid sulfur which is recovered as a product. Nitrogen oxides are converted to nitrogen and ammonia.
The recovery of sulfur compounds, including sulfur oxides, carbonyl sulfide and carbon disulfide, from the tail gas produced by Claus Sulfur Recovery Units in the oil refining and gas processing industry has been disclosed by Beavon in his U.S. Pat. No. 3,752,877. According to Beavon all sulfur species in the Claus tail gas are catalytically hydrogenated to hydrogen sulfide in the presence of hydrogen or a reducing gas. The hydrogen sulfide is then removed from the tail gas using the Stretford process or other liquid phase oxidation processes which produce elemental sulfur as a solid by-product. The liquid phase oxidation processes produce spent solvent which contain hazardous toxics. Hydrogenation of the Claus tail gas and recovery of hydrogen sulfide with a selective acid gas solvent for recycle back as feed to the Claus unit has also been previously known.
The sulfur oxide concentration in the Claus tail gas is about 10 times as high as the concentration of sulfur oxide in flue gas. The Claus Unit tail gas does not contain any excess oxygen, whereas boiler flue gas contains excess oxygen typically ranging between 2 to 5 volume percent which would consume large amounts of valuable hydrogen during the hydrogenation step. The oxygen hydrogenation reaction is highly exothermic which results in a large heat release and the temperature rises in the hydrogenation reactor with typical flue gas oxygen concentrations. Conventional tail gas processing is therefore not directly applicable to stack gas cleanup.
Neal in U.S. Pat. No. 4,755,499 and Magder in U.S. Pat. No. 4,323,544 propose using an alumina sorbent for removing nitrogen oxides and sulfur oxides thereafter regenerating the sorbent with a hot stream of hydrogen sulfide or hydrogen. The sorbent is regenerated at temperatures of up to 650.degree. C. producing elemental sulfur. Hydrogen sulfide, however, is usually not available in the quantities required at most coal burning boiler sites. Also, the 650.degree. C. regeneration temperature requires very expensive equipment.
Vorin et al in U.S. Pat. No. 4,283,380 describe a process in which SO.sub.2 and SO.sub.3 are absorbed by a non-alkalized alumina in the form of sulfates using a fluid bed absorber. The absorbent is subsequently regenerated using a hydrogen sulfide containing gas which produces elemental sulfur. This process requires a high operating temperature of 400.degree. C. for regeneration and a source of hydrogen sulfide gas which is not usually available at a power generating plant. Fluid bed technology is also used with long residence times which requires very large equipment for typical power plants.
Knoblauch et al in U.S. Pat. No. 4,452,772 describes a process in which a fluidized bed of carbonaceous material is heated by combustion with air forming a reducing gas that reacts with a portion of the sulfur dioxides contained in a flue gas thereby producing hydrogen sulfide. The H.sub.2 S to SO.sub.2 ratio from the fluid bed is controlled at 2 to 1. The reactor temperature is regulated so that elemental sulfur is subsequently formed and recovered by Claus reaction technology. The primary disadvantages of this process are the very high operating temperatures of 850.degree. C. to 950.degree. C. required in the fluid bed and the requirement to control both the temperature and the reducing gas produce by air flow regulation. No NOX reduction is achieved by the process and considerable sulfur compounds are contained in the emitted tail gas in the form of COS and other sulfur-containing species from the Claus reaction.
Fornoff in U.S. Pat. Nos. 3,988,129 and 3,829,560 describes a process in which a molecular sieve can be used to recover sulfur dioxide from the effluent of a sulfuric acid process. The molecular sieve is regenerated by purging with hot air and recycling the desorbed gas back through the sulfuric acid process. Flue gas compositions from coal or high sulfur fuel oil boilers are very similar to those of sulfuric acid plant tail gas. Molecular sieve adsorption followed by regeneration with a reducing gas is proposed within the process steps of the present invention. The reducing gas reacts with sulfur oxides and NOX in the subsequent processing steps.
It is a general object of the present invention to provide a flue gas treatment process for boilers and power plants burning low and high sulfur fossil fuels whereby sulfur oxide removal and nitrogen oxide elimination from the flue gas is achieved.
It is a further object of the invention to provide a flue gas treatment process in which the sulfur oxides present in the flue gas from boilers and power plants burning low and high sulfur fossil fuels (solid or liquid) are economically removed from the flue gas combustion products and chemically converted to elemental sulfur.
It is yet another object of the invention to provide a flue gas treatment process for boilers and power plants burning low and high sulfur fossil fuels whereby sulfur is recovered as a liquid elemental sulfur product and oxides of nitrogen are partially converted to non-toxic nitrogen and ammonia gases.
It is another object of the present invention to provide a flue gas treatment process which can be retrofitted to the exhaust duct of fossil fuel combustion apparatus for sulfur oxide removal and nitrogen oxide elimination from the flue gases of such apparatus.
These and other objects and advantages of the present invention will become apparent from the following summary and detailed description of the invention together with the accompanying process flow drawing.